IR 05000334/1993022

Insp Repts 50-334/93-22 & 50-412/93-23 on 930928-1025. Violations Noted.Major Areas Inspected:Plant Operations, Maint,Engineering & Plant Support

ML20059G342
Person / Time
Site:	Beaver Valley
Issue date:	10/29/1993
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20059G332	List: IR 05000334/1993022 ML20059G329
References
50-334-93-22, 50-412-93-23, NUDOCS 9311080074
Download: ML20059G342 (31)

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U. S. NUCLEAR REGULATORY COMMISSION REGION I.

Report Nos.

93-22

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93-23 Docket Nos.

50-334 50-412 License Nos.

DPR-66 NPF-73

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L Licensee:

Duquesne Light Company One Oxford Center 301 Grant Street I

Pittsburgh, PA 15279

Facility:

Beaver Valley Power Station, Units 1 and 2

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Location:

Shippingport, Pennsylvania

.i Inspection Period:

September 28 - October 25, 1993

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Inspectors:

Lawrence W. Rossbach, Senior Resident Inspector i

Peter P. Sena, Resident Inspector

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Scot A. Greenlee, Resident Inspector j

David C. Lew, Project Engineer Richard A. Rasmussen, Reactor Engineer l

Approved by:

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W[zarus@ef, Reactor Projects Section 3B Date

i Inspection Summary

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This inspection report documents the safety inspections conducted during day and backshift

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hours of station activities in the areas of: plant operations; maintenance and surveillance;_

.l engineering; plant support; and safety assessment / quality verification.

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i 93110B0074 931102 i

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PDR ADOCK 05000334'-

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EXECUTIVE SUMMARY Beaver Valley Power Station Report Nos. 50-334/93-22 & 50-412/93-23 Plant Operations i

Operator and plant response to a complete loss of offsite power and Unit I reactor trip was very good. All safety systems at both units functioned as designed, and no significant complications were encountered. Support by off-shift senior reactor operators during the

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event was a strength. The equipment response at Unit 2 demonstrated the strong management safety focus on maintaining safety equipment availability during the refueling outage.

Minor reactor coolant pressure boundary leakage was identified at Unit 1 following the reactor trip. The subsequent plant cooldown and drain-down to repair the leak was completed safely and competently with good supervisory and management oversight. The Unit 2 drain-down for refueling was conducted safely, but operators did not adequately

follow the draining procedure. The failure by the operators to follow the procedure is considered a violation, but is not being cited because of the minor safety significance and i

corrective actions completed by the licensee.

Refueling operations at Unit 2 were conducted safely. However, stronger oversight by the

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refueling senior reactor operators should have identified some minor procedure problems and

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knowledge deficiencies.

Maintenance i

Two separate instances of poor work practices and controls resulted in two safety-significant incidents. The control and coordination of switchyard maintenance on the Unit 2 main generator output breaker was inadequate as this activity resulted in a loss of offsite power event for both units. Additionally, the technicians did not fully understand the protection schemes associated with this breaker. In a separate incident, workers failed to properly install a temporary containment penetration seal per the work documents. This resulted in the faih:re to establish containment closure during the movement of irradiated fuel inside containment. This is an apparent violation of technical specifications.

- Contrary to the above incidents, the repair of a Unit 1 reactor coolant system leak was well

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'I planned and executed. Iessons learned from a similar leak repair in 1991 were applied, which contributed to the smooth completion of this activity. Comprehensive steam generator tube examinations were also completed at Unit 2.

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(EXECUTIVE SUMMARY CONTINUED)

Engineering The licensee's resolution of a generic design deficiency associated with the AMSAC at both units was very thorough. The design change to fix the deficiency was well developed and the post-maintenance test instructions were sufficiently detailed. Unit I was operating at the time the AMSAC deficiency was discovered. The Unit 1 basis for continued operation was acceptable with the exception of identifying compensatory or contingency measures. The AMSAC design deficiency was not well communicated to all reactor operators at Unit 1.

During the previous operating cycle, Unit 2 experienced a failure of one reactor coolant system (RCS) resistance temperature detector (RTD). The cause of the failure was determined to be inadequate thermal insulation installation. The problem was common to all Unit 2 RCS loop RTDs. All of the degraded RTDs are being replaced during the refueling outage. The Unit I has similar RTDs. The licensee established a sound basis for continued operation of Unit I with potentially degraded RTDs. Following the Unit I reactor trip, the RTDs were found correctly installed.

The Independent Safety Evaluation Group (ISEG) was noted as performing critical self-assessments oflicensee activities with sound recommendations to line management for improvement. Also, the ISEG's review of industry events has been effective in identifying safety issues at Beaver Valley.

Plant Suptwrt The assessment of several events during this reporting period by shift supervisors was found to be correct. Two incidents, a reactor coolant pressure boundary leak, and the offsite transportation of a potentially contaminated injured man, were properly and timely classified as unusual events. The loss of offsite power event did not result in an emergency action level being met or exceeded; thus, no event classification was required.

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TABLE OF CONTENTS

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I EXECUTIVE SUMMARY

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TABLE OF CONTENTS

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1.0 MAJOR FACILITY ACTIVITIES

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2.0 PLANT OPER ATIONS (71707, 93702).......................... 1

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2.1 Operational Safety Verification...........................

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2.2 Unit I and 2 Loss of Offsite Power......................., 2

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2.3 Unit 1 Reactor Coolant 1.rak, Cooldown and Draindown.....

..... 4 2.4 Unit 2 Refueling Operations............................. 4 2.5 Unit 2 Reactor Coolant System (RCS) Drain-Down for Refueling'......

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3.0 M AINTENANCE (62703, 61726, 71707)

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3.1 Maintenance Observations..............

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3.2 S urveillance Observations.............................. 8 3.3 Reactor Trip and Loss of Offsite Power Caused by Switchyard Maintenance

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3.4 Turbine Overspeed Protection System Testing.................. 9 3.5 Unit 1 Reactor Coolant System Leak Repair...................

3.6 Inadequate Seal Established in a Unit 2 Containment Penetration

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3.7 Unit 2 Steam Generator Tube Eddy Current Examinations

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4.0 ENGINEERING '(71707, 90712, 92700, 40500)

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4.1 Independent Safety Evaluation Group..........

4.2 Unit 1 Refueling Bridge Misalignment

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4.3 Notice of Deviation (50-412/93-13-02)(Closed) and AMSAC Design

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l Deficiency.........

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4.4 Unit 2 Resistance Temperature Detector (RTD) Failure...........

4.5 Review of Written Reports.............................

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Table of Contents.

5.0 PLANT SUPPORT (71707, 93702, 92709)

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5.1 Radiological Controls...............................

5.2 Secu ri t y........................................

5.3

. Hou sekeepi ng....................................

19-5.4 C h e m i stry.......................................

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5.4.1 Unresolved item 50-412/93-14-02 (Open)

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5.5 Emergency Preparedness.............................. 21

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5.5.1 Transporting Potentially Contaminated Injured Person Unusual Eve n t -..................................... 21 5.5.2 Loss of Offsite Power Event

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5.5.3 Unit 1 RCS Pressure Boundary Leak Unusual Event

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5.6 Inspection of Strike Contingency Plans

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6.0 ADMINISTR ATIVE.........

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6.1 Preliminary Inspection Findings Exit

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6.2 Attendance at Exit Meetings Conducted by Region-Based Inspectors...

6.3 NRC Staff Activities 24=

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DETAILS 1.0 MAlOR FACILITY ACTIVITIES Unit 1 operated at full power from the beginning of this inspection period until October 12 when the unit tripped following a loss of offsite power to the site. Safety systems functioned as designed and the unit was stabilized in Mode 3 (hot standby). This event is described in more detail in Sections 2.2,3.3, and 5.5.2. An Unusual Event was declared on October 13 due to an unisolable leak from a reactor coolant loop isolation valve. The unit was brought to Mode 5 (cold shutdown) to repair the leak. This is discussed in more detail in Sections 2.3,3.5 and 5.5.3. At the end of this inspection period the unit was in Mode 5 to repair an electrical fault that occurred in a reactor coolant pump motor during heatup.

Unit 2 remained in a refueling outage throughout this inspection period. An Unusual Event was declared on October 9 due to a potentially contaminated injured person being transported to a local hospital as described in Section 5.5.1. ~he loss of offsite power on October 12 had little effect on Unit 2 since the core had previously been offloaded to the spent fuel pool and the emergency diesel started automatically as designed. This event is discussed in more detail in Section 2.2.

2.0 PLANT OPERATIONS (71707,93702)

2.1 Operational Safety Verification

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Using applicable drawings and check-off lists, the inspectors independently verified safety system operability by performing control panci and field walkdowns of the following systems: fuel pool cooling and purification; primary component cooling; emergency boration; temporary reactor coolant system level indication; auxiliary feedwater, and diesel

generator fuel oil. These systems were properly aligned. The inspectors observed plant

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operation and verified that the plant was operated safely and in accordance with licensee procedures and regulatory requirements. Regular tours were conducted of the following

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plant areas:

Safeguards Areas

Control Room

Service Buildings Auxiliary Buildings

Turbine Buildings Switchgear Areas

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Access Control Points

Intake Structure

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Protected Areas

Yard Areas

Containment Penetration Areas Spent Fuel Buildings

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Containment Buildings i

Diesel Generator Buildings

r During the course of the inspection, discussions were conducted with operators concerning

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knowledge of recent changes to procedures, facility configuration, and plant conditions. The inspectors verified adherence to approved procedures for ongoing activities observed. Shift turnovers were witnessed and staffing requirements confirmed. The inspectors found that

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J control room access was properly controlled and a professional atmosphere was maintained.

I inspectors' comments or questions resulting from these reviews were resolved by licensee

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personnel.

Control room instruments and plant computer indications were observed for correlation

between channels and for conformance with technical specification (TS) requirements.

Operability of engineered safety features, other safety related systems, and onsite and offsite.

l power sources were verified. The inspectors observed various alarm conditions and l

confirmed that operator response was in accordance with plant operating procedures.

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Compliance with TS and implementation of appropriate action statements for equipment out of service was inspected. Logs and records were reviewed to determine if entries were

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accurate and identified equipment status or deficiencies. These records included operating

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logs, turnover sheets, system safety tags, and the jumper and lifted lead book The

inspectors also examined the condition of various fire protection, meteorological, and seismic j

monitoring systems.

2.2 Unit 1 and 2 Loss of Offsite Power (

l On October 12,1993, at 3:07 p.m., a 90 percent (about 720 MW) turbine generator load rejection occurred at Unit 1 due to a loss of offsite power event. The loss of offsite power j

affected both units, as the.138 Kv and 345 KV buses were stripped of their loads. This event j

was initiated by maintenance activities in the switchyard and is discussed in Section 3.3.

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Due to the massive load rejection, the turbine tripped on mechanical overspeed (110 t

percent). The electrical overspeed trip also actuated at i11 percent. Within 0.01 seconds of r

f the turbine trip, the reactor tripped on positive neutron flux rate. The licensee has evaluated the reactor protection system response and concluded that it was proper. The increase in

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turbine generator output frequency during the overspeed condition caused the reactor coolant

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pumps to speed up. The increased reactor coolant flow increased the heat removal rate from j

the core, and thus a negative moderator temperature coefficient added positive reactivity.

l Westinghouse has also informally reviewed this event and considered the positive flux rate

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trip to be consistent with the expected reactor protection system response.

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During the turbine overspeed condition, the overspeed protection circuit (OPC) setpoint of 103 percent was reached as indicated by the sequence of events recorder. However, the

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generator output breaker is shut. When the output breaker is closed, the generator is locked into the electrical grid frequency and the turbine control system maintains the unit at

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synchronous speed. Although the OPC is defeated in these circumstances, the mechanical

. t and electrical overspeed turbine trip protection is still available. Westinghouse

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documentation indicates that with a mechanical overspeed trip at 110 percent, the terminal i

speed would still be below the 120 percent design overspeed. The use of OPC in this j

manner is a result of a 1989 design change to eliminate the potential for spurious actuation to

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cause a turbine / reactor trip. This design is accurately reflected in the Updated Final Safety Analysis. However, the licensee is currently re-evaluating the appropriateness of this design.

Turbine overspeed protection system testing is discussed in Section 3.4.

Due to the emergency bus undervoltage conditions on loss of offsite power, both emergency diesel generators auto started and properly sequenced on the required safety loads without

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complication. -No safety injection signal was initiated. Natural circulation was established due to the loss of power to the reactor coolant pumps. A heat sink was maintained via

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auxiliary feedwater flow and the steam generator atmospheric dump valves. The main

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condenser steam dumps were not available since the main steam isolation valves were shut as required by procedure. This action was taken due to dual indication on the reheater steam-isolation valve, FCV-MS-100C, per Emergency Operating Procedure, E-O, Response Not Obtained, Step 4. Power to the offsite distribution network was restored by " system" at 3:16 p.m. Forced reactor coolant flow was re-established at 3:33 p.m., by starting reactor

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coolant pump 1C. Plant loads were restored to normal offsite power by 4:21 p.m., and the diesels were secured. The plant was then maintained in stable hot standby conditions at

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547oF.

Unit 2 was in a refueling outage when offsite power was lost. All fuel had been removed from the reactor vessel and placed in the spent fuel pool. One emergency diesel generator

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(EDG) was secured for maintenance, the other was in standby. The standby EDG started automatically and restored power to its associated emergency bus. Safety related loads were

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then sequenced onto the emergency bus as expected. The operators manually restored spent

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fuel pool cooling. Offsite power was restored in nine minutes. No significant complications were encountered at Unit 2 during the event. This demonstrated the strong safety focus that Duquesne Light Company has maintained during the outage. The licensee has done an excellent job of insuring the availability of safety equipment necessary to maintain safe

shutdown conditions.

The resident inspectors noted that, contrary to the Unit 2 Updated Final Safety Analysis

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Report, a safety injection pump was one of the loads that were automatically started during the event. The licensee is also looking at the following items (related to Unit 2) as a result of the event: 1) The 480 V emergency response facility (ERF) substation loads had to be manually loaded on their respective 480 V buses following restoration of power. Some licensee personnel think that the ERF substation programmable controllers should have automatically restored the loads. 2) Some electronic process control circuits were damaged by the electrical transient. The licensee is attempting to determine the root cause of the

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In summary, the response of both units to the shedding of substation loads and the subsequent loss of offsite power was very good. All safety equipment responded as J

designed, and the operators at both units handled the event professionally and without error.

'l The support provided by the offshift senior reactor operators to the shift supervisors was also-j beneficial in evaluating plant conditions and response.

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2.3 Unit 1 Reactor Coolant Leak, Cooldown and Draindown

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' Following the reactor trip on October 12, with the plant stable in hot standby, the licensee

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identified a reactor coolant leak from the vicinity of RC-27. This valve is part of the disk pressurization system which taps directly into the body of cold leg loop stop valve MOV RC-591. The reactor coolant loop stop valves, MOV-RC-590 through 595 are provided with.

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a disk pressurization system which ensures minimum main seat leakage for plant maintenance. Due to the insulation surrounding the loop stop valve and disk pressurization line, the licensee was unable to pinpoint the exact source of the leak. The licensee believed

l the leak to be reactor coolant pressure boundary leakage, and thus declared an Unusual Event (see Section 5.5.3). Based on the information the licensee had on the leak, including

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experience with leakage on a similar line, the decision to declare the Unusual Event was i

appropriate. Visual inspection of the leak indicated that it had existed prior to the reactor j

trip based on the amount of boric acid buildup. The inspectors reviewed the reactor coolant

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leak rate calculations and noted no increasing trend of unidentified leakage prior to the-i reactor trip. Unidentified leakage rate on October 11 was 0.026 gpm.

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The inspectors observed the actions by the operators to cool the plant down to cold

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shutdown, including initiating residual heat removal (RHR). Overall, this activity was well controlled and conducted in a safe and deliberate manner. The inspectors also observed the

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evolution to drain the reactor coolant level to the reactor vessel Dange. Two independent i

level transmitters and a standpipe were available for level indication. The draindown was appropriately stopped at about 4 percent cold calibrated pressurizer level when these-instruments did not agree within 5 inches. The 'A' level transmitter was vented and

recalibrated and the standpipe was flushed. Prior to recommencing the evolution, all level i

instrmnents were verified within specification. The draindown was completed without

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incident. The operators appropriately monitored RHR pump amps and flow to ensure RHR j

pump performance was not affected by reactor coolant level changes. The operations

manager also secured all switchyard maintenance while the plant was in this drained configuration to ensure a reliable offsite power supply was maintained. The inspectors also found the operators to be very knowledgeable on determining reactor coolant heatup rate in the event of a loss of RHR (per Abnormal Operating Procedure 1.10.1). Overall, the

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draindown was safely completed by attentive and competent operators with good supervisory i

and management oversight, j

2.4 Unit 2 Refueling Operations

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The inspectors observed and reviewed the licensee's pre-refueling and refueling activities to i

ensure that they were completed and controlled in accordance with technical specifications, i

Specifically, the inspectors: 1) reviewed and selectively inspected activities that established-j the plant conditions necessary to refuel; 2) reviewed the licensee's procedures for reactor

vessel head removal, reactor vessel upper internals removal, and fuel movement in the refueling cavity; and 3) observed the removal of the reactor vessel head, removal of the i

reactor vessel upper internals, and removal of fuel from the reactor vessel.

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The pre-refueling activities reviewed and observed by the inspectors were found to support the technical specification requirements for refueling. However, during refueling, the licensee found that they failed to establish adequate containment closure. A spare penetration used to pass steam generator eddy current cables into containment was not properly scaled.

Fuel movement was stopped until the licensee adequately sealed the penetration. The licensee's failure to establish adequate containment closure during refueling operations is discussed in more detail in section 3.6 of this report.

The reactor vessel head and upper internals package were removed by Master Lee personnel, under the supervision of a Duquesne Light Company refueling supervisor. The evolutions were well coordinated and controlled, and implementation of lessons learned from industry experiences was evident. Radiological controls support for these evolutions was very good, and indicated a good "as low as reasonably achievable" perspective.

The movement of fuel from the reactor vessel to the spent fuel pool was done by Master Ixe personnel, under the supervision of a licensed senior reactor operator (SRO). During fuel movement observations, the inspectors asked the manipulator crane operator to explain the cause of a locked-in overload indicator. As part of his explanation, the operator mentioned that the manipulator crane continued to move about two feet in the upward direction after the overload light came on. The function of the overload circuit is to stop upward movement of the manipulator crane if the force on the crane is too high. This function is intended to prevent fuel assembly damage in the event that the assembly becomes stuck or snagged.

Technical specifications require that the overload cutout set point be less than 2700 pounds.

The inspector immediately asked the refueling SRO why fuel movements were continuing if the operation of the crane overload cutout was in question. The SRO stopped fuel movement and investigated the situation. The SRO was aware that the overload indicator came on, but he thought it came on as the crane reached the top of its travel. The crane operator thought that the light was malfunctioning, but believed that the actual cutout circuit was still operable. The crane vendor was called in to verify proper operation of the crane. He found -

that the overload cutout circuit was functioning as designed. The overload set-point, however, was set too close to the weight of the heaviest fuel assemblies. The set-point was adjusted from 2380 to 2430 pounds to increase the crane's operating margin. The refueling SRO concluded that the crane operator was mistaken about his observation that the crane continued moving after the overload condition occurred.

The inspectors concluded that the crane was operating properly. However, the crane operator's knowledge of the crane interlocks was lacking because he should not have continued moving fuel based on his observation. Miscommunication between the SRO and the crane operator also contributed to the continuation of fuel movement when operation of the overload cutout circuit was in question. The licensee reviewed this event with all three shifts of refueling personnel. Operation of the overload cutout and the importance of accurate communications were stresse a i

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1 The inspectors compared the manipulator crane operating procedure (2RP-4R-3.3) to actual-

crane operations. The inspectors noted several differences between the procedure and actual operations, and in one case the procedure incorrectly described one of the interlocks. These i

deficiencies were discussed with the Refueling Manager. The Refueling Manager halted fuel

handling operations and performed a detailed review of the procedure. He found that the

crane operators were operating the crane according to management expectations. The procedure was determined to be incorrect. The procedure was new, and apparently had not

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been validated in the field. The procedure was corrected and all refueling personnel were briefed on the changes before resuming fuel offload. Overall, the inspectors were satisfied

that the movement of fuel was done safely; however, the refueling senior reactor operators

.j should have identified the procedural deficiencies and the misconception associated with the

crane overload cutout.

I 2.5 Unit 2 Reactor Coolant System (RCS) Drain-Down for Refueling In preparation for removing the reactor vessel head, the Unit 2 RCS was drained to just j

below the vessel flange. The procedure used for this operation was 20M-6.4.1 " Draining

the RCS for Refueling." 20M-6.4.1 requires that five level indicators come on scale and l

agree to within 5 inches when pressurizer level in less than 5 percent. If agreement within 5'

inches is not obtained, the procedure requires the operators to stop the drain-down until the

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condition is corrected. The two senior reactor operators (SROs) supervising the drain-down j

authorized exceeding the 5 inch correspondence requirement. Their decision was based on

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experience and the pnysical configuration of each of the indicators. The inspectors l

concluded that the decision to continue with the drain-down was based on sound technical

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reasoning, but questioned the authority of the SROs to make such a decision. Chapter 48 of

the Unit 2 Operating Manual requires that procedures which effect the nuclear safety of the j

plant be followed as written unless deviation is required by an emergency or casualty i

situation.

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The inspectors compared the actual configuration of the temporary level indicators to the.

configuration discussed in 20M-6.4.1. The inspectors found that the installed configuration l

was not supported by the procedure. The installed configuration was supported by a diagram

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generated specifically for the refueling outage. The diagram was not part of the draining

procedure. Apparently, operations personnel concentrated more on the diagram than the procedure. The installed configuration did provide the operators with accurate level

indications.

i The problems with the drain-down procedure were discussed with the Unit 2 Operations

Manager. He confirmed that the SROs should have stopped the draining procedure when the

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indicators reached 5 inches of deviation. To correct the procedure issues, the Operations Manager stated that he would: 1) have the RCS draining procedure reviewed and corrected;

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2) reemphasize procedural compliance and the importance of correcting procedures with personnel involved with exceeding the 5 inch correspondence requirement; and 3) initiate

operator training on procedural compliance and importance of correcting procedures. The

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failure by operations department personnel to follow 2OM-6.4.1 is considered a violation of Technical Specification 6.8.1 which requires that the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33 be established and implemented. Regulatory Guide 1.33 Appendix "A" lists draining of the RCS as one of the recommended procedures. The inspectors considered this to be of minor safety significance and the corrective actions were promptly completed. This violation is not being cited because the criteria of Section VII.B of the Enforcement Policy were satisfied.

3.0 MAINTENANCE (62703,61726,71707)

3.1 Maintenance Observations The inspectors reviewed selected maintenance activities to assure that: the activity did not violate Technical Specification Limiting Conditions for Operation and that redundant

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components were operable; required approvals and releases had been obtained prior to commencing work; procedures used for the task were adequate and work was within the skills of the trade; activities were accomplished by qualified personnel; radiological and fire prevention controls were adequate and implemented; QC hold points were established where required and observed; and equipment was properly tested and retumed to service. Unless otherwise indicated, the activities observed and reviewed were properly conducted without any notable deSciencies.

The following maintenance work requests (MWRs) were observed and reviewed.

• MWR 023999 Reactor Coolant Leak Repair at MOV-RC-591 (see Section 3.5)

MWR 024197 Remove Linear Indication on MOV-RC-590 (see Section 3.5)

MWR 023998 Calibrate Temporary Reactor Coolant Loop Level Transmitter

MWR 024272 Install and Test AMSAC Time Delay Seal-in Function (see Section 4.2)

MWR 016735 Install and Route Steam Generator Eddy Current Cables (see Section

3.6)

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MWR 021974 2CHS-MOV-8131A Repair and Testing

The inspectors observed and reviewed two of the tasks covered by MWR 021974:-1) limit

switch reinstallation following grease replacement; and 2) torque switch replacement. The

procedures used were: 1) 1/2 CMP-75-MOV OVERHAUL-6E "Limitorque Motor Operator

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Type SB/SBD/SMB-00 Overhaul"; and 2) 1/2 CMP-75-TORQUE SWITCH-1E " Installation

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and Maintenance of Torque Switch in Limitorque Operators." The inspectors concluded that:

1) the procedures were of good quality and were properly used by the electrical maintenance

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technicians; 2) the maintenance personnel were knowledgeable about the valve construction, operation and maintenance; 3) the maintenance site job supervision was good; and 4) job coverage by radiological controls and quality control personnel was appropriate.

3.2 Surveillance Observations The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly

calibrated and used, technical specifications were satisfied, testing was performed by qualified personnel, and test results satisfied acceptance criteria or were properly dispositioned. The operational surveillance tests (OSTs), Beaver Valley Tests (BVTs),

'j reactor surveillance tests (RSTs), loop calibration procedures (LCPs), and maintenance i

surveillance procedures (MSPs) listed below were reviewed. The observed surveillance activities were properly conducted without any notable deficiencies unless otherwise indicated.

1/2 RST -49.1 Core Physics Monitoring During Refueling.

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1/2 LCP-24-AMSAC-I AMSAC Functional Test and Calibration (see Section 4.3)

OST 1.45.3 Seismic Monitoring Instrumentation Monthly Channel Check

OST 1.49.2 Shutdown Margin Calculation

3.3 Reactor Trip and Loss of Offsite Power Caused by Switchyard Maintenance

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The loss of offsite power that occurred on October 12,1993, was a result of maintenance in the substation switchyard. A maintenance crew had done a routine inspection of one of the Unit 2 main transformer output breakers (breaker 352) a couple of days before the event.

During the inspection, they found a cracked linkage for a set of breaker auxiliary contacts.

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The breaker has a total of three stacks of auxiliary contacts. All three contact stacks are

connected by mechanical linkage which moves the contacts when breaker position is changed.

j On October 12, the maintenance crew replaced the cracked linkage and inadvertently shifted

the shaft on the associated stack of contacts by 180 degrees. Breaker 125 Vdc control power

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was never isolated from the breaker, so the contact stacks were energized.

i The maintenance crew started breaker timing checks after the linkage was repaired. When

the breaker was shut, the auxiliary contacts affected by the linkage replacement operated out

of sequence. This caused two relays in the Unit 2 relay room to receive simultaneous

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operate and reset signals. Smoke was subsequently found coming from these relays. The

site relay crew isolated the smoking relays and notified the substation maintenance crew of the problem. The maintenance crew stopped the timing checks and began to investigate.

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They found the misaligned contact deck and corrected the problem. Then, the maintenance

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crew started checking all auxiliary contacts for misalignment, using a Fluke multimeter on a

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continuity scale. Apparently, the technician using the Fluke accidentally setup a path to

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supply 125 Vdc power, through the meter, to the substation underfrequency tripping relays.

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The relays picked-up and, as designed, opened ten substation breakers. This isolated the

nuclear station from all sources of power on the grid, and left Unit I supplying only 10 percent ofits rated load. The load shed and loss of grid synchronization caused Unit I to trip (see Section 2.2 of this report for additional details on plant response).

The function of the underfrequency relays was to isolate certain loads when grid frequency'

i dropped due to system overload. The intent of the design was to shed enough load to restore

grid frequency and, thus, keep the nuclear units on-line. The licensee isolated the i

underfrequency load shedding circuit since it obviously did not perform as intended. The

licensee means to leave the circuit isolated, and will evaluate whether to upgrade the design.

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The resident inspectors had the following observations concerning the event:

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The licensee's investigation to determine the cause of the underfrequency circuit l

actuation was thorough and accurate.

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Control and coordination of maintenance on the Unit 2 output breaker was inadequate.

The work on the breaker auxiliary contact switch decks should not have started until

the possible circuit interactions were-understood.

l The licensee has temporarily placed tighter controls on maintenance in the switchyard. Entry into the switchyard has always required approval from a shift supervisor. Entry into the i

switchyard for maintenance now also requires approval from the Unit 1 or Unit 2 Operations l

Manager. Approval is only granted after a detailed review of the work, and development of j

any necessary control measures. Additionally, the system operator must call the site _before

sending a traveling operator to the switchyard, to explain the purpose of the trip. The l

licensee is evaluating permanent changes to procedures for control of maintenance in the j

switchyard. The resident inspectors assessed that the interim controls should be adequate to j

prevent a recurrence of the October 12 problem.

i 3.4 Turbine Overspeed Protection System Testing

Following the Unit 1 main turbine overspeed trip on October 12, the resident inspectors

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reviewed the licensee's turbine overspeed testing program. The focus of the review was to

ensure that overspeed protection is available during overspeed trip testing. The inspectors

reviewed the Unit I and Unit 2 overspeed protection system configurations and the

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l operational surveillance tests for the overspeed trip systems. Both units perform similar.

j turbine overspeed trip tests, which actually cause the turbine to trip on overspeed. The trip i

tests are not performed on-line (i.e., the main transformer output breakers are open during-the tests) and at least two overspeed protection systems are operable during the tests. The i

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The Unit 1 overspeed trip systems are designed such that during pedestal checks the mechanical and electrical overspeed trips are disabled. If the Unit I main transformer output breakers are open, the overspeed protection controller (OPC) will provide the turbine with overspeed protection. If the Unit 1 main transformer output breakers are shut, the OPC is disabled. Thus, pedestal checks at Unit I with the main transformer output breakers shut would remove all turbine overspeed protection. The Unit 1 pedestal checks procedure does allow the checks to be done on-line; however, the surveillance test schedule specifically prohibits pedestal checks on-line without the permission of the Operations Manager. The Unit 1 Operations Manager stated he would not allow pedestal checks on-line. He also noted that the Unit 1 sh

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supervisors understand that pedestal checks are not to be performed on-1

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The Unit 2 overspeed trip systems contain more redundancy than the Uni 7ystems.

At least two overspeed protection systems would be operable during pedestal checks.

The Unit 2 pedestal checks procedure does allow performance on-line, but the test is typically not performed in this condition.

The inspectors concluded that main turbine overspeed trip testing at Unit I and Unit 2 is conducted safely. As long as pedestal checks are not conducted with Unit 1 on-line, turbine overspeed protection should be available at both units when the turbines are rolling.

3.5 Unit 1 Reactor Coolant System Leak Repair A reactor coolant leak was identified in Unit 1 originating from a weld connecting a small 3/4 inch diameter disk pressurization line to the body of cold leg loop stop valve MOV-RC-591. Due to the location of the leak, it could not be isolated from the reactor coolant system. Previously, on January 17,1991, (see NRC Inspection Report 50-334/91-02), an identical leak occurred on loop stop valve MOV-RC-593. These leaks are similar in that both occurred on the weld connecting the disk pressurization line to the body of the loop stop valve. The root-cause analysis of the 1991 weld failure was determined to be outer diameter initiated cyclic fatigue. As corrective action to reduce the possibility of future failures, the piping length of the lower disk pressurization tap for all loop stop valves was shortened, and the heavy blind flange was replaced with a swagelok coupling. This design change was also completed at Unit 2.

The repair of the RC-591 leak was similar to the repair of RC-593 in 1991. The reactor coolant system was depressurized and drained to reduce the head of water on the leak. The disk pressurization line was cut with a pipe cutter and a tapered plug was tamped into the

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body of the loop isolation valve. This activity took about 15 seconds and about 1 gallon of water was discharged through the opened piping before being successfully plugged., The disk pressurization line was then completely removed, and a cap was welded over the initial plug.

Lessons learned from the original 1991 repair were applied, as a jacking screw was used to maintain the plug fully seated during the welding. The licensee also used mockups to re-validate the repair methodology and to train the mechanics. The inspectors considered the mockup to be a good initiative; however, it could have been more realistic with respect to worker orientation and confined conditions. Overall, the use of lessons learned and good performance by the mechanics resulted in a successful repair. Also, good job preplanning helped to minimize the time the reactor coolant system was in a drained configuration to less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The radiological controls during this repair are discussed in NRC Inspection Report 50-334/93-25.

The root cause of this weld failure is currently under investigation. The licensee appropriately has completed liquid penetrant examinations of the remaining loop isolation valve / disk pressurization line socket welds for both units. One linear indication was found at Unit 1 and three linear indications were found at Unit 2. These 5dications have subseque.ntly been removed by light filing.

3.6 Inadequate Seal Established in a Unit 2 Containment Penetration On September 25,1993, the licensee established a temporary seal in a containment penetration to provide passage for steam generator eddy current cables into the Unit 2 j

containment. The seal was established by injecting silicone foam into the penetration from the containment. However, the workers did not inject. silicone under the lower cable tray in l

the penetration. This left an open path from the containment to the cable vault. The quality i

control inspector assigned to the job did not notice the error.

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On October 3,1993, at 9:34 p.m. the licensee started the first core alterations of the

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- refueling outage. On October 6 at about 9:15 a.m., a Bechtel supervisor noticed air blowing out of the spare penetration. Air pressure had built-up in containment because the containment purge and exhaust valves were shut. The valves were shut (as required by l

technical specifications) because one of the two associated process radiation monitors had

failed the day before. The licensee was notified of the problem and fuel movement was

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stopped at 9:35 a.m. Approximately 132 fuel assemblies (out of 157) had been moved from

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the reactor vessel to the spent fuel pool. The licensee notified the NRC Operations Officer i

of the event at 12:15 p.m.

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The Unit 2 cable vault is normally maintained at a slightly negative pressure by the l

supplementary leak collection and release system (SLCRS). The SLCRS discharge for this

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area is normally unfiltered; however, radiation monitors sense the discharge activity levels j

and will cause the system to shift to a filtered mode of operation if high activity is detected.

The inspectors verified that SLCRS and the associated radiation monitors were operating

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during the period that closure was not maintained. The SLCRS flow rate from the east side cable vault (the side with the defective penetration) is normally about 400 cubic feet per minute. The potential discharge rate from the penetration has not been determined.

The licensee had a similar problem with temporary penetrations in March of 1992 (violation 50-412/92-07-02). They offloaded fuel with two penetrations sealed with fire retardant fiber

and tape. The penetrations were not leak tight. The licensee's current method of temporary seal installation is a result of corrective actions for the 1992 violation.

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The inspectors reviewed the maintenance work request paperwork associated with the

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temporary penetration, and interviewed the workers who installed the temporary seal. The inspectors concluded that the workers failed to install the original seal according to the work document. Additionally, the inspectors noted that the only test of the seal's adequacy was a visual inspection. The licensee is conducting an investigation to determine why the workers and the quality control inspector did not follow the work document. The inspectors also watched the installation of more seal material in the temporary penetration on October 6.

The work document was available at the work site and was properly followed. The licensee also tested the seal on October 6 by establishing a differential pressure across the penetration and looking for air flow. The differential pressure was obtained by allowing pressure to

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buildup in containment.

The licensee's failure to establish containment closure prior to core alterations is an apparent

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violation of technical specifications. Technical Specification 3.9.4 requires that each penetration providing direct access from the containment atmosphere to the outside

atmosphere shall be closed by an isolation valve, blind flange, manual isolation valve, or approved functional equivalent during core alterations or movement of irradiated fuel within r

the containment.

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3.7 Unit 2 Steam Generator Tube Eddy Current Examinations

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The licensee conducted an extensive steam generator tube examination program to assess the integrity of tubing in the Unit 2 steam generators. An NRC inspection of the licensee's inservice inspection program included portions of the steam generator tube eddy current

examinations and is reported in NRC inspection report 412/93-21. The licensee's eddy current examinations and corrective actions are summarized below.

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The Unit 2 steam generator examinations consisted of bobbin coil examination of 100% of inservice tubes. Inconclusive bobbin coil results and areas of interest, such as the U-bends,

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were further eddy current examined with a rotating pancake coil. Only two tubes were l

plugged due to indications greater than technical specification allowable. Eight tubes were plugged due to loose parts wear. All of the tubes plugged due to loose parts wear were in

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the B steam generator and all of these tubes were also stabilized to prevent movement. The loose parts were apparently parts of two deburring bits, and were removed with the exception

of one piece which is firmly lodged in place. The deburring bits were probably associated

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with a "J" tube modification which was done before initial startup. The tubes in contact with this remaining object were among those plugged and stabilized. The largest number of tubes plugged (48) were due to indication of dings in the free span of the U-bends. The U-bends

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had not previously been examined with the rotating pancake coil and so these indications may have been preexisting.

There are 3,376 tubes in each Unit 2 steam generator (SG). The tube plugging status at the

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completion of tube work during the current refueling outage (4R) is as follows:

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A SG B SG C SG Total Tubes plugged in 4R

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Tubes plugged pre-4R

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33 Total tubes plugged

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121 Percent plugged 1.3 0.9 1.3 1.2

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The inspectors considered that the licensee's steam generator tube examinations were comprehensive. The licensee's actions for the remaining foreign object were adequate. The r

total number of tubes plugged due to service induced indications is very low and indicates good steam generator performance.

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4.0 ENGINEERING (71707, 90712, 92700, 40500)

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4.1 Independent Safety Evaluation Group The Independent Safety Evaluation Group (ISEG) of Duquesne Light Company (DLC) is

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responsible for evaluating the licensee's nuclear activities, including examination of operating characteristics, industry advisories, NRC issuances, and other sources of operating experience information. Recommendations are made, where appropriate, on improving the quality of safety of plant operations. The functions of the ISEG are explicitly defined in the Unit 2 Technical Specifications (TS). The professional backgrounds of the five ISEG

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members are consistent with the TS requirements. Additionally, the length of experience and variety of expertise (i.e., engineering, quality control, licensing, start-up testing) of the ISEG r

indicates that its members are properly qualified to perfarm useful assessments and provide

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recommendations with proper bases.

t ISEG activities have been previously inspected and are documented in NRC inspection

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reports. This includes the ISEG pre-outage shutdown safety review (NRC Inspection Report 50-334/93-04) and the identification of a previously unanalyzed release path with the

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potential to exceed 10 CFR 100 radiological limits (NRC Inspection Report 50-334/93-01).

The ISEG's activities in these two areas were previously deemed as being indicative of this organization's excellent safety perspective.

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The ISEG has been active in reviewing significant events, both in-plant and industry wide.

For example, the root-cause evaluations of the Unit I reactor trip and Unit 2 reactor trip / safety injection were noted by the inspectors to be comprehensive and in depth. The ISEG review ofindustry events is prioritized based upon a formalized criteria. This criteria includes, in part: events at " sister" plants; safety related component failure of equipment which is known to be installed at Beaver Valley; and common mode failures of redundant safety-related components. This criteria has allowed the ISEG to promptly identify and review those events with the highest safety significance or applicability to Beaver Valley.

These reviews by the ISEG have been effective as noted by the following at Beaver Valley:

pursuit of an AMSAC design deficiency similar to Indian Point 3; identification of improper hydrogen analyzer testing as initially reported by Surry; position development on the loss of high head safety injection due to the alternate minimum flow and water hammer concerns based upon Information Notice 92-61; and identification of a post loss of coolant accident containment leakage path based upon a Diablo Canyon event. The ISEG also performs a final review (after routing) of all NRC Information Notices for which other site departments have primary responsibility for review. Active participation with the Westinghouse Owners Group (WOG) by the ISEG chairman has also allowed the ISEG to be cognizant of industry wide incidents, and areas for planned plant improvement. Currently, the ISEG is coordinating the licensee's input to the WOG review of the NRC draft of shutdown technical specifications.

The line organization, including senior management, has often requested the ISEG to perform a variety of special assignments, including evaluations and investigation of issues. Per the request of senior management, the ISEG is currently investigating the root cause of the repetitive failure to maintain containment integrity during refueling. Other special assignments have included acting as controllers during the 1992 full participation emergency exercise. The ISEG chairman was also involved in a multidisciplined assessment of the motor operated valve program in which significant performance issues have been identified.

The inspectors reviewed this report and considered it to be an objective assessment which was critical of many aspects of the licensee's program. The recommendations contained in the report were justified with a proper basis for each. This assessment was submitted to senior managers with the authority to implement corrective actions.

The inspectors also performed a review of recommendations provided by the ISEG in other reports, including the fire protection program assessment, Unit 1 shutdown safety review, and the Unit 2 reactor trip root-cause report. The ISEG maintains a tracking mechanism of all ISEG recommendations. Recommendations remain in this tracking system until independently verified as being implemented. Line organization personnel are required to notify the ISEG if recommendations are not accepted. These issues would then require resolution by senior management, including the Senior Vice President. The majority of recommendations have been accepted for implementation (87 percent for 1992). The

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inspectors reviewed selected completed recommendations and verified their proper implementation.

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Overall, the inspectors considered the ISEG to be especially effective in identifying safety issues for applicability to Beaver Valley. The reports issued by the ISEG were thorough and well done with properly justified recommendations.

4.2 Unit 1 Refueling Bridge Misalignment The inspector reviewed an Independent Safety Engineering Group (ISEG) report concerning a site specific issue. The issue involved the operation of the refueling building crane on May 11,1993, during which refueling personnel attempted to shift the crane slightly by operating the crane against the stops. This action was taken to minimize rubbing between the crane wheels and rail.

Site management requested ISEG to review this event to determine the safety significance of the event. The ISEG concluded that this event had minimal safety significance. The bases for this conclusion were that the stops were designed to withstand an impact from the crane, and in the unlikely scenario that the stops fail, the seismic guard would prevent the crane from derailing and falling. Additionally, the ISEG considered the potential for this action to distort the crane calibration for aligning the trolley with the correct fuel assembly. However, the ISEG determined that such a gross distortion would be unlikely, and, if gross distortion did occur, it would be noticed. The inspector concluded that the ISEG's conclusions were sound.

The ISEG highlighted to management the belief by some refueling section personnel that this activity, though subsequently determined to be not safety significant, was an acceptable method to operate the crane and without a procedure. However, Duquesne Light Company (DLC) indicated that this belief was contrary to its philosophy and expectations. Upon review of this finding, DLC reemphasized its expectations to pertinent refueling section personnel to prevent recurrence of this activity. Consistent with the minor safety significance of the issue, DLC issued a Level I problem report.

The inspector reviewed Procedure IMSP-60.03-M, Spent Fuel Pool Crane Hoist Test, and noted that the procedure was silent on operating the crane against the stops. The inspector concluded that the ISEG appropriately satisfied the request from management to determine the safety significance of a site event. In addition, a peripheral issue identified by the ISEG, concerning personnel not understanding DLC expectations and standards, was brought to the attention of management, and actions commensurate with the significance of the event were taken.

4.3 Notice of Deviation (50-412/93-13-02) (Closed) and AMSAC Design Deficiency This deviation involved the licensee's failure to test the Unit 2 AMSAC time delays and setpoints as identified by the inspectors. The licensee had previously committed to this testing per implementation of the anticipated transient without scram (ATWS) rule. As corrective action, the licensee developed the appropriate test procedure. Operational

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functional controls testing during the previous outage did not identify any potentially degraded conditions. Loop calibration procedure 2LCP-24-AMSAC-I satisfactorily verified the feedwater flow serpoints of 25 percent and the turbine power setpoints of 40 peroent with l

no discrepancies. This test also verified the calibration of AMSAC timer B-5 whose purpose

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is to ensure AMSAC remains armed long enough to perform its function in the event of a i

turbine trip. No deficiencies were identified with this timer. Deficiencies were, however, identified with variable timer B-3 which is designed to delay the initiation of AMSAC as a

function of turbine power (impulse pressure). The time delay is 25 seconds at 100 percent

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power and ramps to 150 seconds at 40 percent power. The purpose of this time delay is to

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allow the reactor protection system to generate a protective signal before AMSAC initstes.

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Because a loss of load is one of the events for whic' AMSAC mitigation is required, the

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timer must recognize the loss of turbine load has occurred and yet maintain the timer at the s

pre-event value. However, Beaver Valley has identified that AMSAC initiation delay timer I

does not lock in the power level from which it has been activated. Under conditions of

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changing turbine power (i,c., turbine trip), the lack of the seal-in requirement would cause a'

the time delay to be outside the time delay envelope. This envelope is based on limiting

peak reactor coolant system pressure within the ASME stress limit. This design deficiency is i

due to the fact that Westinghouse Owners Grouplopical report WCAP-10858-P-A,

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Revision 1, "AMSAC Generic Design Package," did not include this seal-in function. This seal-in function of the AMSAC delay timer is only discussed in the cover let:er which l

transmitted this WCAP report to the NRC (letter OG-87-35, August 7,1987, to J. Lyons, j

USNRC). This design omission appears to be a generic issue to Foxboro units, as Ginna -

Power Station has also identified this identical deficiency. This omission was not found l

during the system acceptance tests at the vendor facility, the initial installation tests, or the

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periodic surveillance tests. This is due to the fact that the tests involved static conditions of

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turbine load, not dynamic conditions of turbine load. The dynamic test simulates coincident loss of feedwater with a turbine trip. The development of this dynamic testing resulted from the notification by Ginna personnel to Beaver Valley of this design deficiency. The i

Duquesne Light Company's Independent Safety Evaluation Group also had just initiated a

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review of Information Notice 92-06, Supplement 1, (Indian Point 3 AMSAC Reliability)

l which discussed the need for dynamic AMSAC testing.

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The Unit 1 AMSAC system is a similar Foxboro unit which also has this design deficiency.

l Accordingly, the licensee implemented the guidance of generic letter 91-18 and developed a l

basis for continued operation (BCO). The inspector reviewed the BCO and found it to be acceptable with the exceptic, of identifying compensatory or contingency measures. The

BCO did not take credit for mnction recovery procedure FR-S.1, which directs operator

action in the event of an ATWS. Additionally, the communication of this design deficiency

to reactor operators (i.e., those who would implement FR-S.1) could have been better, as j

only one of six operators interviewed by the inspectors were found to be knowledgeable of

this issue.

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Minor design change 2860 has tabsequently been implemented at Unit 1 to upgrade the logic software to include the timer seal-in function. The inspectors observed the installation and.

testing of the software and concluded that the AMSAC system now meets its original design specifications per WCAP-10858-P-A, Revision 1. This modification is planned for the Unit 2 AMSAC during the current outage. Overall, the design changes were well developed and the post-maintenance test instructions were sufficiently detailed. Also, the licensee's pursuit and resolution of a potentially generic design issue was thorough. The inspectors had no further concerns. This deviation is closed.

4.4 Unit 2 Resistnnce Temperature Detector (RTD) Failure During the previous cycle, Unit 2 experienced a failure of one of the three loop 'C' hot leg RTDs (see NRC Inspection Report 50-412/93-01). The RTDs are used as inputs to the reactor controls and protection circuits. The licensee continued to operate the unit, per technical specifications, with the two remaining RTDs in loop 'C' and the required bias applied. Investigation of the failure during the current outage revealed that all of the Raychem insulation on the wiring internal to the RTD termination head had melted completely away. The affected RTD was located in the 12 o' clock position. Further inspections of other RTDs revealed evidence of insulation degradation due to heating effects,

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although less severe. The hot leg RTDs located in the 12 o' clock position on loops 'A' and

'B' were specifically noted to have discolored (browned) insulation.

A root-cause analysis by the licensee, with the assistance of the RTD vendor, identified that inadequate installation of thermal insulation on the reactor coolant piping where the RTDs-penetrate the loop, was the caure of the failure. The inadequate thermal insulation at the RTD penetration allowed the RTD housing temperature to rise above design due to convective heating. The wiring insulation is rated to 140oF for a 20-year qualified life.

Degraded RTD wiring insulation will result in electrical shorts or indicated reactor coolant temperature spikes. The RTDs were installed at Unit 2 in 1990, during a design change which eliminated the bypass manifolds. The design change package referenced plant installation procedure PIPS-M10.2 for thermal insulation instructions. However, the details of the qualification testing report provided by the vendor were not fully translated into the installation procedure as the PIP contained only general insulation installation instructions.

As corrective action to the degraded RTDs, all Unit 2 RTDs are being replaced this outage.

Unit I has similar RTDs, which were installed in 1989. Initially, the licensee completed an operability assessment per Generic Letter 91-18. The inspectors reviewed the licensce's assessment and concluded that a sound basis for continued operation existed. Specifically, an RTD failure is detectable via continuous monitoring during plant operations, and technical specifications allow continued plant operation with a failed RTD (provided the required bias is applied to the remaining RTDs).

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temperature was tound to be 119oF. The qualified life of the RTDs was then determined to be 23 years. The inspectors reviewed these calculations and found them to be valid.

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Overall, the inspectors considered the licensee's actions to be appropriate, given the safety function of the RTDs. The decision to replace all Unit 2 RTDs was proper, given that the RTDs had varying degrees of degradation due to heating. Also, the Unit 1 basis for continued operability properly focused on determination of operability vice restoration of full qualification (i.e., correcdve action) per Generic Letter 91-18. The adequacy of control of

the installation of the RTDs which resulted in insufficient insulation, is unresolved pending

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further NRC review (50-412/93-23-01).

4.5 Review of Written Reports

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The inspectors reviewed Licensee Event Reports (LERs) and other reports submitted to_ the NRC to verify that the details of the events were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspectors determined whether further information was required from the licensee, whether cencric implications were indicated, and whether the event warranted further onsite follenup. The following LER and.

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Part 21 Report were reviewed:

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Unit 1 Potential 10 CFR 21 Condition:

Valve Alignment Charging Pump Operation.

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This issue was previously inspected in NRC Inspection Report 93-210.

Unit 2 93-04 Steam Generator Blowdown Isolation While Troubleshooting DC Ground

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This engineered safety features (ESF) actuation event was inspected as discussed in NRC

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inspection report 93-05/05. The above LER was reviewed with respect to the requirements of 10 CFR 50.73 and tae guidance provided in_ NUREG 1022. In addition, the inspectors reviewed the corrective actions described in the LER. The inspector observed that breakers 8-1 on DC panels 2-06 and 2-07 were labeled with permanent caution and ESF actuation warning tags. These breakers control auxiliary feedwater pump steam supply valves SOV 105 A and B and although there are six steam supply valves, these are the only two that produce a steam generator blowdown isolation signal. The inspectors considered the corrective actions to be adequate. The event report was closed based on in-office review of l

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the event report and the described onsite inspection.

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i 5.0 PLANT SUPPORT (71707, 93702, 92709)

5.1 Rndiological Controls

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Festing and control of radiation and high radiation arcas were inspected. Radiation work permit compliance and use of personnel monitoring devices were checked. Conditions of step-off pads, disposal of protective clothing, radiation control job coverage, area monitor operability and calibration (portable and permanent,, and personnel frisking were observed on a sampling basis. Licensee personnel were observed to be properly implementing their radiological protection program.

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5.2 Security

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Implementation of the physical security plan was observed in various plant areas with regard I

to the following: protected area and vital area barriers were well maintained and nu

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compromised; isolation zones were clear; personnel and vehicles entering and packages being delivered to the protected area were properly searched and access control was in accordance with approved licensee procedures; persons granted access to the site were badged to indicate whether they have unescorted access or escorted authorization; security access controls to

vital areas were maintained and persons in vital areas were authorized; security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding

position requirements, and that written procedures were available; and adequate illumination j

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was maintained. Licensee personnel were observed to be properly implementing and

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following the Physical Security Plan.

5.3 llousekeeping

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Plant housekeeping controls were monitored, including control and storage of flammable material and other potential safety hazards. The inspectors conducted detailed walkdowns of accessible areas of both Unit I and Unit 2. Housekeeping at both units was acceptable.

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5.4 Chemistry

5.4.1 Unresolved Item 50-412/93-14-02 (Open)

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An unresolved item was identified in Inspection Report No. 50-412/93-14 concerning particulate concentration in the emergency diesel generator (EDG) fuel oil storage tanks.

The item contained two separate issues. The first issue was the consistency of the fuel oil sample results. The second issue was the determination of the source of the contamination and subsequent corrective actions.

Regarding the first issue, the inspector observed chemistry technicians obtaining a sample from the No. 2EDG-Tk21 A fuel oil storage tank via an all-levels sampling method. The all--

levels sampling method involved lowering a stoppered, metallic bottle to the draw offlevel,

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then raising it at a rate such that the bottle was approximately 75 percent full when it emerged from the fuel oil. The specification of 75 percent full was based on not filling the bottle prematurely near the lower levels of the tank, and, thereby, not obtaining any fuel oil

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near the upper levels. The sampling technique was specified per ASTM D4057-81, Standard i

Practice for Manual Sampling of Petroleum and Petroleum Products.

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Two deficiencies in the licensee's use of the all-levels sampling method had the potential to introduce errors into the results. The inspector noted that the sample bottle appeared to be-i full when it emerged from the tank. Although this was not readily apparent because the l

bottle was not transparent, the inspector noted that the combined volume of three samples

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taken from the tank exceeded that of a one-liter container. The capacity of the sample bottle, t

however, was approximately 360 milliliters. Consec;iently, there was no assurance that the

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upper levels of the tank were sampled. Another deficiency was the configuration of the sample point of the tank. The normal sample point was through a two inch pipe, which extended to the lower portion of the tank. Consequently, the sample taken was representative of all levels of the pipe vice all levels of the tank. Additionally, during the technician's insertion of the sample bottle into the pipe, resistance caused by the bottle -

rubbing against the pipe was encountered. This rubbing had the potential to increase the

particulate concentration results.

The licensee was aware that the normal sample point was deficient in that the rubbing between the bottle and pipe caused higher than actual particulate concentration results. As a result, the licensee was developing a composite sampling method, which will draw a sample from three discrete regions of the tank, and weigh the samples according to the amount of fuel in the tank. This method was also specified in ASTM D4057-81. The method would not use a metallic bottle, which would minimize any rubbing with the piping. Additionally, the licensee stated that a modification was being considered to provide a different sampling point for the tank, which would not be through a pipe that runs to the lower portion of the -

tank.

l The inspector also observed a portion of the analysis for the particulate concentration. Based on the portions observed, the inspector concluded that the technique for the analysis was.

good. Care was taken to prevent inadvertent contamination of the filter paper, a critical element in obtaining accurate results. The inspector did not consider that the analytical-j method or technique contributed significantly to inconsistent particulate concentration results.

The inspection review previous results to identify whether consistent results from sample to -

j sample were being performed. The inspector noted that several samples taken on the same day but from different locations showed varying results. Typically, the method of sampling by the all-level sampler was higher than either by sampling with a tygon tube or the alternate j

sample point, which involved removal of a man-hole cover. The inspector concluded that the j

current sampling method caused the results to be variable but conservative.

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• Regarding the second issue, the licensee had not completed its evaluation on the source of

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contamination experienced in June 1993. At that time, however, the source was speculated to be combustion products or lube oil in the fuel, which returned to the storage tanks from the diesel engine via a drain line. Subsequently, however, the licensee obtained samples from the drain line. The amount of fuel return noted was small (characterized as a fast

trickle). Additionally, the particulate concentration in the returned fuel was 6 parts per

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million, within the particulate concentration limits of technical specifications. Based on the

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new information obtained, the drain line did not appear to be the source of the

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contamination.

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In summary, although the licensee's current sampling technique contained denciencies, the i

sample results were conservative. This conservative error provided assurance that the j

particulate concentration in the tanks was within the technical specification limit. The licensee was developing a new method to sample the fuel oil tanks, and was considering a

modification to change the sampling point. The licensee had not completed the root cause L

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for the high particulate concentrations experjenced in June. This unresolved item remains

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open pending (1) the licensee's implementation of a new sampling method and (2) the licensee's completion of their investigation into the high particulate concentrations.

l 5.5 Emergency Preparedness

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5.5.1 Transporting Potentially Contaminated Injured Person Unusual Event

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On October 9,1993, at 12:40 p.m., the licensee declared an Unusual Event due M

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transporting a potentially contaminated injured person to a local hospital. A worker inside l

the Unit 2 containment building had slipped on a ladder and suffered a laceration with severe-

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bleeding. The severity of the injury was not realized until the worker became Qint. When the severity of the injury became known, the control room was immediately notified and -

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dispatched the emergency squad to provide assistance. A harness was used to move the I

worker from a platform to a stretcher and the worker was removed from the containment and

placed in a waiting ambulance. Due to the need to transport the worker to an offsite medical i

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facility as quickly as possible and due to the background radiation at the location of the injury, the licensee was unable to survey the individual for contamination or remove the

harness and protective clothing from the worker prior to leaving the site. Accordingly, the injured worker was considered contaminated. The shift supervisor appropriately declared an-

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Unusual Event shortly after the ambulance departed the site for the Medical Center of Beaver County.

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All initial notincations were completed within the prescribed time limits. Two radiological-

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control personnel from the site accompanied the worker to the hospital. The licensee reports that subsequent surveys of the injured worker, those involved in the event, the ambulance,

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and the hospital, indicated no loose contamination. Fixed contamination was found on the harness and protective clothing which were returned to the site. The event was terminated at

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1:40 p.m. and followup notifications were completed in a timely manner. Overall, the

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emergency squad demonstrated effective and timely response to this event. The health physics support was also good since there was no spread of contamination from inside the containment building.

5.5.2 Loss of Offsite Power Event

The inspectors reviewed the licensee's emergency preparedness plan (EPP) implementing

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procedures to ensure that the loss of offsite power event that occurred on October 12 was properly assessed. During this event, an unusual event (UE) was not declared. The loss of AC power emergency action-level (EAL) requires a UE to be declared upon "a loss of AC

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sources exceeding the limiting condition for operation (LCO) that results in a required shutdown," (per technical specification 3.8.1.1). This technical specification states that with two of the required offsite AC circuits inoperable, demonstrate operability of the two diesel generators (unless they are already running) and restore the two offsite circuits to operable i

status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. During this event, the LCO was not exceeded as both diesels were operable and operating and both offsite circuits were restored in 9 minutes. However, indicator number 2 for this criterion was met (Lc., offsite class 1E distribution system

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inoperable). The inspectors concluded that the EPP indicators were not consistent with the EAL criterion. The inspectors considered that the shift supervisor's assessment of this event -

for classification purposes was adequate. The licensee does plan on revising the EAL

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criterion for loss of AC power (power operations and shutdown conditions) based on the NUMARC pilot EAL project. Under the new EAL criterion, a UE would be declared in the

event of a " loss of offsite power for greater than 15 minutes." Following internal review by the licensee per 10 CFR 50.54(q), the new EAL criterion should be implemented by December 1993. The licensee also plans on submitting the entire set of NUMARC EALs to the NRC for approval.

5.5.3 Unit 1 RCS Pressure Boundary Leak Unusual Event On October 13,1993, at 7:55 a.m., the licensee declared an unusual event due to pressure boundary leakage in Unit 1 that results in a required shutdown. The plant was already in hot standby conditions when this leak was identified. Per technical specifications, the plant must be in cold shutdown within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> of identifying pressure boundary leakage. The

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inspectors reviewed this event and deemed it to be properly classified. All required notifications to local, state, and federal agencies were completed. Follow-up notifications were completed twice per shift as required by the EPP until event termination. The unusual event was terminated on October 14 at 3:00 a.m. when cold shutdown conditions were reached.

5.6 Inspection of Strike Contingency Plans The labor agreement between Duquesne Light Company (DLC) and the International

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Brotherhood of Electrical Workers (IBEW) expired on October 1,1993. IBEW represents all DLC union personnel except security officers. The contract was extended while

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negotiations continued. A memorandum of agreement on a proposed one-year contract.

between the licensee and IBEW was signed on October 23,1993. The proposed contract was ratified by a vote of the union membership on October 27,1993.

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i Although a strike was not anticipated, the inspector reviewed the licensee's strike-

contingency plans because of the potential for a job action following expiration of the contract and contract extensions.

a The inspectors reviewed the licensee's contingency plans to determine the licensee's ability to meet minimum requirements for staffing the facility, assuming that Unit I remained in operation and Unit 2 remained shutdown. The licensee's ability to staff with qualified

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individuals, plant management, licensed and nonlicensed operator shift positions, maintenance, health physics, and other personnel responsible for operational or safety functions was verified. The availability of qualified personnel to implement the site emergency plan and to continue to implement the site seemity plan was verified. The inspectors concluded that the minimum number of qualified personnel were available to insure condnued proper operation and safety.

6.0 ADMINISTRATIVE

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6.1 Preliminary Inspection Findings Exit

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At periodic intervals during this inspection, meetings were held with senior plant management to discuss licensee activities and inspector areas of concern. Following conclusion of the report period, the resident inspector staff conducted an exit meeting on October 26,1993, with Beaver Valley management summarizing inspection activity and findings for this period.

6.2 Attendance at Exit Meetings Conducted by Region-Based Inspectors During this inspection period, the inspectors attended the following exit meetings:

Inspection Reporting Dates Subiect Report No.

Insnector 10/8/93 Unit 2 ISI and Erosion / Corrosion 93-21 P. Patnaik-10/22/93 Unit 2 Izak Repairs and Stress Analysis 93-25 J. Carrasco f

10/22/93 Outage Radiological Controls 93-25/26 J. Nick

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6.3 NRC Staff Activities Inspections were conducted on both normal and backshift hours: 47.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of direct inspection were conducted on backshift; 31.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> were conducted on deep backshift. The

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times of backshift hours were adjusted weekly to assure randomness.

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R. Barkanic, Pennsylvania Department of Environmental Resources, visited the site and the inspectors on October 5 and 20 and discussed inspection activities and the licensee's performance.

W. Lazarus, Chief, Region I Section 3B, visited the site on October 5, 6,25, and 26 for

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discussions with the inspectors and utility management, and to tour the site.

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. pedsat negleser / Vol w,.Na> 133 / PHday; h# 10. telut / Notices

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3eygg.

-Send commaanse to:%e Secretaryof theComadesion.UA ENCLOSURE 2-NuclearRegdetery em Waebinstem.DC 30s:5. ATIN:

Dockettes andServios Branch.

Handdelivercommente to:One White

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Flint North.11855 Rockvius Pike.

Rockvius. MD between 7:45 a.m. to 4:15 p.m Federalworkdays. _

Copies of commente may be examined at the NRC PeblicDocueent Room.21:0

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L Street.NW.(lower Level). -

Washington.DC -

pas puumeenseemeavsesscaerracT:.

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James Liebesmen. Director. Office of

Enforcement.UA Nuclear Regulatory l

e-i==Aa= Washington.DC 20555

(301-aowr41).

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sumammeramsesamanoem

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%e NRCe serventpohey on -

enforcement ooniemacos is addressed in -

i Section V of the latest reviolon to the

"GeneralStatement of Peugy and

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Procedure for Enforcement Actione.**

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.i (Enforossent Poucy)to CFR part 2.

appendiaCthatweep kli=had on

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- February ta.1get(sr PR E791).The Enforcement states that. :

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" enforcement wiR not -

normeEybe spes to the public.".

However,theCommissionhas decided toimplementalutalproyam to determalmewhaterto meistain the i

curmet pokerwitbreegendto :

enfesteseamlageforescemor to adopt a.

7 tee-YearTrtal PrtMyesa for~

new pokey that would aHow most -

enforcement cashte be open to

,l CondmotingOpen rnfereensent attendemosby all===have of the pubhc. '

Conferensees Por sy Statement l

Policy Statenest-Aamesv Nacisar Pagulatory r-e s.=

m

1. "*""

. %e NRCle impla-a=*iar a two. year f

euemamervine Naciser Regelatory -

trialpapesa to suow pubiac observatism of selected enforcement Comademies (NRC) le loseing ele poucy condammess.%e MitC will esonitor the

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statement on the 4=r3====*=eiaa of a.

propees anddetenminewhether ta two year trial propen to aHow asiscted establish a permansat policy for enforcement conferences to be open to.

en=hmeing enforcement

attendance by allmembers of the confomenos se an assessment of generalpuhuc.nie poucystatement the fouewingcriteria-descnbes the two-year trialproyees (1)Whether the fact that the andinfonme the public of how to get coedammeswas openimpacted the

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i infonnation on upcondag open.

NRCs abuity to condent a meaningful enforcement conferences.

condammes and/or kuplement the NRC's.~

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natum:This trial propan te effective on d PF"E i

July 10.1983,while cosamente on the

- (2) Whether the open conference 5 r

program are being received. Subesit --

impacted thelh's participation in.

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comments on or before the n 2 the condemons:

of the trial program scheduled for July (3)Whether the NRC expended a

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11,199L Commente received after this

't date willbe w.dd sd ifit is practical signiarmasamount of resources in -

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maidne the conference public: and,

to do so. but the Commission is, able to assure consideration only for c5mmente (4)De extent of public interest in received on or before this date.

opening the enforcement conference.

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r Federed Register / Vol 57. No.133 / Friday, July 10,19a2 / Nossoas 3:

L Criterte For Seleseles Open three categortes oflloemeems will be sub}ect to r==a==as emeenseg.that

, Enfasesseneg e-s======

cosenerdal operating reactors, signe, beamers, postere. etc., not larger Enforcement conferences wulnot be W 1 and o6er h wM 6en the penitted, and that cpen to the poblacif the enformmans wul coneest of the romanag types of disruptiw pareces amay be renurved.

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Licensen.

Each regiemel amos will contance to acuou ' <==i-t =#a4-(t) W be taken against an IL A -

' - - Open Enforcement maduct es enforcement contemece

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pr=dage la accordance with regional individual, or if the action, though not h

tak:n against an individual turns on pescuce.The enforeneumt omference As soon as itis detarmined thet an wh:ther an individualhas -h4 wdl contione to be a moedag between d

enf reement conference wul be open to the NRC and thelicensee. Whde the pubbe observation, the NRC wdl orallF eaforcement conference is open for lav es s'gnWs nt perstmnel n tif the licenses that the enfomamet T

public observation, it is not open for failures where the NRC has requested e niesce W2 pen b puMc pubhc perucipet on.

th:t theIndividual(s) involved be mbe " P*rt 0

• • A CY pmms atten&ng open enforcent present at the conference:

pmgrem and send the heensee a copy of confances am remindad that(1) the (3)Is based on the Endings of an NRC I* *I

"

es Office of Investigations (01) report or C*n8*","tD be *skM to appannt vialanaam dismaeed at open

• Pr05mm-enforna=nant E-f -,= are subject to (4) Involves safeguards informadon.

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8M2 Privacy Actinformation,orother further mtw and may be sub ect to t

N,$"NR h

E'i '

inf tion which could be considered sch

,

Enfaroement conferences involving

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statements of views or expressmns of

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p pinion made by NRC employees at m: dical misadministrations or State liaison officers that an j$ enf r ement c nferences or the overexposures wul be open assuming edo w =d e b h tha confersnoe can be conducted

• " " ' * " "

scheduled and that it is open to public represent final u,.

mmations or behefs.

without dielaaW the exposed oburvada Individual's name. In addition, I" *d S 8 """

"

ne NRC Intends to announce open

" "[pmgra"m "b ame "ce aM n

cnforeaseent osoferveces will not be enforcement couderescas to the pabbc oPen m the puWeif the cafemnae wul normally at least to working deys la Mdce. pemns

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8 en 28 OPen enfamment codences ha omdocted by telephone or the edvance of the enforcement conferena wu pmided anw.3a mmty a conference wiB be cond acted et a through the follomag meha-rel tively smalllicensee's facility.

(1) Nodoes postedin the Pabus submit written comuments anonymously Finally, with the approval of th*

Docmment Roosu de W hh amnwnts Executive Director for Operations.

(2) ToB freetalephone mammegas and mil eubuquently be forwarded to the d de OSce d Enfamnannt for enforcement conferences win not be (3) Toll-free electronic bauenn board miew and considerstbn.

open to the publicin special cases mme where good canes has been shewn after atabif ahment of the toB4me Deted at seekville, wo, sus rih d.y a J.;y balancing the beneSt ofpubbe mesesse eyetems, the public mey call N-observa$om againat the potential hapact (301) 4ss 473g to obtain a reco'tting of For the Ma a.gpwy r'--son _

on the assacy's anlercamant action in a upcomregopen

.J,m -.t Sement 5. CMk.

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particular case.

conferences.The NRCw D isene anothee-Secrwaryof the C

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i 32 NRC wul etrive to conduct open Federal Register nodce afher the foll-free [FR Doc. 50-1633 med 7-e.-ams m)

enforcement conferences durms the-mesonge ryseerne are estebHmbed.

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two-year snal program in sa:ordance To ese6st the NRC in==Mng with the following thres goals:

appropriate arrangessents to support

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(1) Appr-=taly 25 percent of all public observation of endorcesosat 31754 eligible adoroement confersaces aanferwoose. individuale interested ta coridetad by the NRC will be open for attentting a particular enfore=mant puhtsc abamoon:

confance should nodry seindMdal Corrections

"='8 "**

(2) At least one open enforcement ideedbed in the meeting notice voL sr. No tas conference wdl be mnA--din each of anmuncing the open enforcement the regional offices; and conf:sreece ne later than Sve busmess Prider. July 17. m (3) Open enforcement confer===*

days price to the enforcesment will be conducted wrth a variety of the conference.

types of licensees.

NUCt. EAR REOtAATORY To evoad poumtialbias in the M.Coodecs of Open Enforcement COsanaseereg selection process and to attempt to meet Conferemme

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the three goals stated above, every in accordence with ctarrent practim.

Two Year W N w. W fourth altg bie enforcement conferseco edorcement conferences wdl continue Conducting Open Enforcement involvmg one of three categories of to normally be held at the NRC regional Conferenose; Poincy Statement licensees wtM mormaDy be open to the offices. Members of the pubbe wdl be Correcth public danns the tnal program, allowed access to the NRC regmnal However,in cases where there is an offices to attes;.d open adorcement in notice dcament 92-16233 beginmns ongoing edjudicatory proceeding with conferences in accordance with the on page 30782 in the issue of Priday, ons or more intervenors enforcement

" Standard Operstmg FM*5 For July,10. WL on page 3cm2. In 6a conferenas invoMng issues related to M Lims Security Sopport For NRC second column. under naus. beginning tha subject raatier of the ongoing Heanngs And Meetmgs" pubE3hed in the fifth line. " July 11.19a2,, should adjudicetion may also be opened. For November 1.1W1 (56 FR 56::31). These read,, July IL 1994.

tha purpoem of this trialprogram the procedures provide that visitors may be

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